Considerable expense and effort is currently employed in the energy and chemical processing sectors to conduct necessary inspections of pipelines and other piping systems (e.g., cooling water and process stream piping). Often, these inspections require system shut down and in some cases excavation resulting in the high expenses encountered. As a consequence, such inspections are conducted at periodic intervals rather than continuously. Depending on the size of the interval, however, significant degradation can occur between inspections that can in turn result in unanticipated failures. A common method for inspection of gas transmission pipelines is the use of in-line inspection tools (pigs). A key problem with using pigs is that around 30% of natural gas transmission pipelines in United States are not piggable due to various constraints, such as sharp bends, diameter changes, and valving systems.
In-line inspections of gas transmission pipelines are primarily carried out to measure pipeline wall thickness changes resulting from corrosion and dents resulting from third party damage. According to the US Department of Transportation Office of Pipeline Safety (OPS), internal corrosion caused about 15 percent of all gas transmission pipeline reportable incidents over the last two years, leading to an average of $3 million in annual property damage. Furthermore, fatalities have occurred at pipeline failures associated with internal corrosion. Efforts have therefore been made at developing methods to predict the location of corrosion within pipelines that then reduce the number of sites that require actual physical inspection (either using pigs or through excavation). This method has been termed internal corrosion direct assessment (ICDA).
Though ICDA does prioritize the locations for further pipeline inspections and possible excavation, it does not provide a direct measure if water is actually present at those locations nor does it determine if corrosion is occurring. Pipelines still must be inspected and if the pipe segment is unpiggable, then the pipe needs to be excavated to detect and monitor corrosion.
Another common maintenance problem encountered in gas pipelines, especially in gas distribution systems, is leak detection. Leaks are often due to third party damage, which occurs when construction or excavation crews inadvertently strike underground utility lines. Natural gas distribution systems are constructed using pipes made of either steel or plastic. The utility companies will use manual inspection methods to look for leaks in sections of pipe line. Existing methods are labor intensive and the leak information not timely.
Thus, there is a need for a method and a system for detection of internal corrosion inside metal pipelines that will complement the ICDA method. Furthermore there is a need for remote and real-time monitoring of any type of gas pipelines. Once such a system is in place then gas pipelines can be monitored for corrosion, humidity, gas mixture, gas flow rates and pressure.
Wireless transmission of electromagnetic radiation communication signals has become a popular method of transmitting RF signals, such as cordless, wireless, and cellular telephone signals, pager signals, two-way radio signals, etc. There is, however, no system in place to transmit information using wireless inside gas pipelines.